<p class='bwalignc'> <b>Record Production of 89,135 BOE/d in Q1 2013 Up 4% Over 86,055 BOE/d in Q4 2012</b> </p> <p class='bwalignc'> <b>Q1 2013 Net Income Available to Common Shareholders of $86.0 Million or $0.72 per Diluted Share and Adjusted Net Income of $111.6 Million or $0.94 per Diluted Share</b> </p> <p class='bwalignc'> <b>Q1 2013 Discretionary Cash Flow Totals a Record $401.1 Million</b> </p> <p class='bwalignc'> <b>Niobrara Well in DJ Basin Completed Flowing 861 BOE/d</b> </p>

DENVER (Business Wire) -- Whiting Petroleum Corporation's (NYSE: WLL) production in the
first quarter of 2013 totaled a record 8.022 million barrels of oil
equivalent (MMBOE), of which 87% were crude oil/natural gas liquids
(NGLs). This first quarter 2013 production total equates to a daily
average production rate of 89,135 barrels of oil equivalent (BOE),
representing a 10% increase over the first quarter 2012 average daily
rate of 80,747 BOE per day and a 4% increase over the fourth quarter
2012 average daily rate of 86,055 BOE per day.

James J. Volker, Whiting's Chairman and CEO, commented, “We are off
to a strong start in 2013, our 10th year as a
public company.Production in the first quarter of 2013 grew 4%
sequentially over the fourth quarter of 2012, and we are on track to
post a year-over-year production gain of between 12% and 16%.We
are very pleased with our development plan at our Redtail Niobrara
prospect in the DJ Basin where our most recent completion came in at 861
barrels of oil equivalent per day.We look forward to stepping up
our activity there in the second half of this year.”

Mr. Volker added, “In the Williston Basin, drilling at our Sanish,
Pronghorn, Hidden Bench and Tarpon fields continues to underpin our
production increases.Recent well results at our Missouri Breaks
prospect indicate that this area should also contribute significantly to
future production growth.”

Operating and Financial Results

The following table summarizes the first quarter operating and financial
results for 2013 and 2012:

Three Months Ended March 31,

2013

2012

Change

Production (MBOE/d)

89.14

80.75

10 %

Discretionary Cash Flow-MM$ (1)

401.1

351.9

14 %

Realized Price ($/BOE)

74.77

74.17

1 %

Total Revenues-MM$

613.4

563.7

9 %

Net Income Available to Common Shareholders-MM$

86.0

98.2

(12)%

Per Basic Share

$0.73

$0.84

(13)%

Per Diluted Share

$0.72

$0.83

(13)%

Adjusted Net Income Available to Common Shareholders-MM$ (2)

111.6

122.6

(9)%

Per Basic Share

$0.95

$1.04

(9)%

Per Diluted Share

$0.94

$1.03

(9)%

(1)

A reconciliation of discretionary cash flow to net cash provided by
operating activities is included later in this news release.

(2)

A reconciliation of adjusted net income available to common
shareholders to net income available to common shareholders is
included later in this news release.

Operations Update

Core Development Areas

Williston Basin Development

In the Williston Basin, we control 1,111,802 gross (704,525 net) acres
that target the Middle Bakken, Three Forks, Pronghorn Sand and Red River
formations. Our average acreage cost in this area is $526 per net acre.

Western Williston Basin

The Western Williston Basin includes our Hidden Bench, Tarpon, Missouri
Breaks and Cassandra prospects. These areas represent a total of 182,913
gross (114,454 net) acres. Production from the Western Williston Basin
averaged 6,520 BOE per day in the first quarter of 2013, which
represented a 27% increase over the 5,120 BOE per day average rate in
the fourth quarter of 2012.

Missouri Breaks Prospect. We hold 95,803 gross (65,481
net) acres in the Missouri Breaks prospect, located in Richland County,
Montana and McKenzie County, North Dakota. On March 12, 2013, we
completed the Miller 34-8-1H in the Middle Bakken formation flowing
1,475 BOE per day, our best rate to date in the field. We have now
drilled successful wells on the western, eastern and southern portions
of our acreage.

Southern Williston Basin

The Southern Williston Basin encompasses our Pronghorn and Lewis & Clark
prospects, which encompass a total of 396,482 gross (262,194 net) acres.
First quarter 2013 production from this region averaged 13,800 BOE per
day. This daily rate represents a 52% increase over the 9,055 BOE per
day rate in the first quarter of 2012.

Sanish Field Area

Whiting's net production from the Sanish field averaged 33,300 BOE per
day in the first quarter of 2013, an increase of 16% over the first
quarter 2012 average of 28,790 BOE per day. Whiting continues to
generate strong results from the field. Highlighting recent results was
the completion of the Roggenbuck 21-25H, which was completed in the
Middle Bakken formation flowing 2,053 BOE per day on April 3, 2013. This
well was drilled on the western edge of the Sanish field. The well's
8,463-foot lateral was fracture stimulated in a total of 26 stages.

We plan to initiate a higher density pilot program in the Sanish field
in the second quarter of 2013. If successful, this could add a total of
191 additional Middle Bakken locations. We also plan to refrac several
wells at Sanish in 2013.

Red River Plays

Big Island. We currently hold 176,900 gross (125,530 net)
acres in the Big Island prospect, which is located in Golden Valley
County, North Dakota and Wibaux County, Montana. During the first
quarter of 2013, we completed two successful vertical wells in the Upper
Red River “D” zone at Big Island. The Stecker 32-9 was completed flowing
308 BOE per day on February 18, 2013, while the Davidson 13-19 flowed
226 BOE per day on March 6, 2013. We are now 11 out of 12 in this highly
profitable play.

Starbuck Prospect. We have completed a 283-square-mile 3-D
seismic shoot at our Starbuck prospect and are currently interpreting
the data in order to identify seismic anomalies in the Upper Red River
“D” zone. Our preliminary analysis indicates that there are similar
seismic anomalies at Starbuck as our Big Island prospect, where we have
identified more than 50 separate prospects. We hold 105,664 gross
(91,228 net) acres in the Starbuck prospect, which is located in
Roosevelt County, Montana.

Emerging Plays

Denver Basin: Redtail Niobrara Prospect. We hold a total
of 120,354 gross (87,610 net) acres in our Redtail prospect, located in
the Denver Julesberg Basin in Weld County, Colorado. Our Redtail acreage
currently produces from the Niobrara “B” zone and is also prospective in
the Niobrara “A” and “C” zones as well as the Codell formation. We
estimate that there are up to 35 million barrels of oil in place per
section in the Niobrara “B” zone at Redtail.

Highlighting recent drilling results at our Redtail prospect was the
completion of the Razor 26-3524H, which flowed 812 barrels of oil and
292 Mcf of gas (861 BOE) per day from the Niobrara “B” zone on April 8,
2013. The well has flowed over 600 BOE per day over the last two weeks.
The well's 6,364-foot lateral was fracture stimulated in a total of 32
stages using our new frac design. Whiting holds a 74% working interest
and a 59% net revenue interest in the Razor well, which was drilled on a
960-acre spacing unit.

We currently have one drilling rig running at Redtail. We plan to add a
second rig that is pad capable around mid-year and a third rig before
year-end 2013. Our development plan for the Redtail prospect is to drill
eight wells per spacing unit to the Niobrara “B” zone and four wells in
each spacing unit to the Niobrara “A” zone. In total, we estimate that
we have more than 2,400 gross locations or over 1,200 net locations at
our Redtail prospect.

Delaware Basin:Big Tex Prospect. Whiting's
lease position at Big Tex consists of 93,207 gross (69,163 net) acres,
located primarily in Pecos County, Texas. On January 23, 2013, we
completed the May 2502H flowing 674 barrels of oil per day from the
Upper Wolfcamp formation. The well's peak 30-day average was 397 barrels
of oil per day. The May 2502H is currently producing over 200 barrels of
oil per day. Based on the performance of this well, Whiting has elected
to move a drilling rig to Big Tex in May 2013. We currently plan to
drill at least three horizontal Upper Wolfcamp wells at Big Tex in 2013.

Enhanced Oil Recovery

North Ward Estes Field. Net production from our North Ward
Estes field averaged 8,545 BOE per day in the first quarter of 2013.
Whiting is currently injecting approximately 335 MMcf of CO2
per day into the field, of which about 67% is recycled gas.

Operated Drilling Rig Count

As of April 15, 2013, 23 operated drilling rigs were active on our
properties. The breakdown of our operated rigs as of April 15, 2013 was
as follows:

Region

Northern Rockies

20

Permian Basin

--

Central Rockies

1

EOR Projects:

Postle

1

North Ward Estes

1

Total

23

Other Financial and Operating Results

The following table summarizes the Company's net production and
commodity price realizations for the quarters ended March 31, 2013 and
2012:

Three Months Ended

March 31,

Production

2013

2012

Change

Oil (MMBbl)

6.25

5.58

12

%

NGLs (MMBbl)

0.71

0.66

7

%

Natural gas (Bcf)

6.37

6.60

(4

%)

Total equivalent (MMBOE)

8.02

7.35

9

%

Average Sales Price

Oil (per Bbl):

Price received

$

88.11

$

90.51

(3

%)

Effect of crude oil hedging

(0.85

)(1)

(2.54

)

Realized price

$

87.26

$

87.97

(1

%)

NYMEX oil (per Bbl)

$

94.34

$

102.94

(8

%)

NGLs (per Bbl):

Realized price

$

42.56

$

46.26

(8

%)

Natural gas (per Mcf):

Price received

$

3.80

$

3.43

11

%

Effect of natural gas hedging

-

0.07

Realized price

$

3.80

$

3.50

9

%

NYMEX natural gas (per Mcf)

$

3.34

$

2.72

23

%

(1)

Whiting realized pre-tax cash settlement losses of $5.3 million on
its crude oil hedges during the first quarter of 2013. A summary of
Whiting's outstanding hedges is included later in this news release.

First Quarter 2013 Costs and Margins

A summary of production, cash revenues and cash costs on a per BOE basis
is as follows:

Per BOE, Except Production

Three Months Ended

March 31,

2013

2012

Production (MMBOE)

8.02

7.35

Sales price, net of hedging

$ 74.77

$ 74.17

Lease operating expense

12.45

12.90

Production tax

6.39

6.07

General & administrative

3.60

4.68

Exploration

2.35

1.33

Cash interest expense

2.37

2.19

Cash income tax expense

0.05

0.19

$ 47.56

$ 46.81

First Quarter 2013 Drilling and Expenditures
Summary

The table below summarizes Whiting's operated and non-operated drilling
activity and capital expenditures for the three months ended March 31,
2013:

Gross/Net Wells Completed

Total New

% Success

CAPEX

Producing

Non-Producing

Drilling

Rate

(in MM)

Q1 13

82 / 38.0

1 / 1.0

83 / 39.0

99% / 97%

$ 569.3

Outlook for Second Quarter and Full-Year 2013

The following table provides guidance for the second quarter and
full-year 2013 based on current forecasts, including Whiting's full-year
2013 capital budget of $2,200.0 million.

Guidance

Second Quarter

Full-Year

2013

2013

Production (MMBOE)

8.25 - 8.45

33.80 - 35.00

Lease operating expense per BOE

$

12.30 - $ 12.70

$

12.30 - $ 12.60

General and admin. expense per BOE

$

3.45 - $ 3.65

$

3.45 - $ 3.65

Interest expense per BOE

$

2.60 - $ 2.80

$

2.50 - $ 2.70

Depr., depletion and amort. per BOE

$

25.00 - $ 26.00

$

25.25 - $ 26.25

Prod. taxes (% of production revenue)

8.50% - 8.70%

8.55% - 8.75%

Oil price differentials to NYMEX per Bbl(1)

(

$ 6.50) - ($ 7.50)

(

$ 6.50) - ($ 7.50)

Gas price premium to NYMEX per Mcf(2)

$

0.20 - $ 0.50

$

0.20 - $ 0.50

(1)

Does not include the effect of NGLs.

(2)

Includes the effect of Whiting's fixed-price gas contracts. Please
refer to fixed-price gas contracts later in this news release.

Oil Hedges

The following summarizes Whiting's crude oil hedges as of April 1, 2013:

Weighted Average

As a Percentage of

Derivative

Hedge

Contracted Volume

NYMEX Price

March 2013

Instrument

Period

(Bbls per Month)

(per Bbl)

Oil Production

Three-way Collars(1)

2013

Q2

1,040,000

$ 71.25 - $ 85.63 - $ 113.95

48.5%

Q3

1,040,000

$ 71.25 - $ 85.63 - $ 113.95

48.5%

Q4

1,040,000

$ 71.25 - $ 85.63 - $ 113.95

48.5%

Collars

2013

Q2

294,550

$ 48.17 - $ 90.71

13.7%

Q3

294,450

$ 48.16 - $ 90.70

13.7%

Oct

294,340

$ 48.15 - $ 90.69

13.7%

Nov

194,340

$ 47.96 - $ 85.90

9.1%

Dec

4,340

$ 80.00 - $ 122.50

0.2%

2014

Q1

4,250

$ 80.00 - $ 122.50

0.2%

Q2

4,150

$ 80.00 - $ 122.50

0.2%

Q3

4,060

$ 80.00 - $ 122.50

0.2%

Q4

3,970

$ 80.00 - $ 122.50

0.2%

Swaps

2013

Q2

185,033

$98.50

8.6%

Q3

187,067

$98.50

8.7%

Q4

187,067

$98.50

8.7%

2014

Q1

165,000

$94.75

7.7%

Q2

166,833

$94.75

7.8%

Q3

168,667

$94.75

7.9%

Q4

168,667

$94.75

7.9%

2015

Q1

150,000

$94.75

7.0%

Q2

151,667

$94.75

7.1%

Q3

153,333

$94.75

7.2%

Q4

153,333

$94.75

7.2%

2016

Q1

133,467

$93.50

6.2%

(1)

A three-way collar is a combination of options: a sold call, a
purchased put and a sold put. The sold call establishes a maximum
price (ceiling) we will receive for the volumes under contract. The
purchased put establishes a minimum price (floor), unless the market
price falls below the sold put (sub-floor), at which point the
minimum price would be NYMEX plus the difference between the
purchased put and the sold put strike price.

Whiting also has the following fixed-price natural gas contracts in
place as of April 1, 2013:

Weighted Average

As a Percentage of

Hedge

Contracted Volume

Contracted Price

March 2013

Period

(MMBtu per Month)

(per MMBtu)

Gas Production

2013

Q2

364,000

$5.47

16.4%

Q3

368,000

$5.47

16.6%

Q4

368,000

$5.47

16.6%

2014

Q1

330,000

$5.49

14.8%

Q2

333,667

$5.49

15.0%

Q3

337,333

$5.49

15.2%

Q4

337,333

$5.49

15.2%

Selected Operating and Financial
Statistics

Three Months EndedMarch 31,

2013

2012

Selected operating statistics

Production

Oil, MBbl

6,250

5,583

NGLs, MBbl

710

664

Natural gas, MMcf

6,371

6,604

Oil equivalents, MBOE

8,022

7,348

Average Prices

Oil per Bbl (excludes hedging)

$

88.11

$

90.51

NGLs per Bbl

$

42.56

$

46.26

Natural gas per Mcf (excludes hedging)

$

3.80

$

3.43

Per BOE Data

Sales price (including hedging)

$

74.77

$

74.17

Lease operating

$

12.45

$

12.90

Production taxes

$

6.39

$

6.07

Depreciation, depletion and amortization

$

25.08

$

21.25

General and administrative

$

3.60

$

4.68 ((1

))

Selected Financial Data

(In thousands, except per share data)

Total revenues and other income

$

613,371

$

563,706

Total costs and expenses

$

475,607

$

406,261

Net income available to common shareholders

$

85,994

$

98,201

Earnings per common share, basic

$

0.73

$

0.84

Earnings per common share, diluted

$

0.72

$

0.83

Average shares outstanding, basic

117,788

117,517

Average shares outstanding, diluted

119,263

118,896

Net cash provided by operating activities

$

297,614

$

352,992

Net cash used in investing activities

$

(628,491

)

$

(213,052

)

Net cash provided by (used in) financing activities

$

294,259

$

(145,926

)

(1)

For the three months ended March 31, 2012, the price includes the
effect of a one-time charge under our Production Participation Plan
related to the Whiting USA Trust II divestiture of $1.17 per BOE.

Conference Call

The Company's management will host a conference call with investors,
analysts and other interested parties on Thursday, April 25, 2013 at
11:00 a.m. EDT (10:00 a.m. CDT, 9:00 a.m. MDT) to discuss Whiting's
first quarter 2013 financial and operating results. Please call (866)
515-2911 (U.S./Canada) or (617) 399-5125 (International) to be connected
to the call and enter the pass code 71718725. Access to a live Internet
broadcast will be available at http://www.whiting.com
by clicking on the “Investor Relations” box on the menu and then on the
link titled “Webcasts.” Slides for the conference call will be available
on this website beginning at 11:00 a.m. (EDT) on April 25, 2013.

A telephonic replay will be available beginning approximately two hours
after the call on Thursday, April 25, 2013 and continuing through
Thursday, May 2, 2013. You may access this replay at (888) 286-8010
(U.S./Canada) or (617) 801-6888 (International) and entering the pass
code 52179437. You may also access a web archive at http://www.whiting.com
beginning approximately one hour after the conference call.

About Whiting Petroleum Corporation

Whiting Petroleum Corporation, a Delaware corporation, is an independent
oil and gas company that explores for, develops, acquires and produces
crude oil, natural gas and natural gas liquids primarily in the Rocky
Mountain, Permian Basin, Mid-Continent, Michigan and Gulf Coast regions
of the United States. The Company's largest projects are in the Bakken
and Three Forks plays in North Dakota and its Enhanced Oil Recovery
fields in Oklahoma and Texas. The Company trades publicly under the
symbol WLL on the New York Stock Exchange. For further information,
please visit http://www.whiting.com.

Forward-Looking Statements

This news release contains statements that we believe to be
“forward-looking statements” within the meaning of the Private
Securities Litigation Reform Act of 1995. All statements other than
historical facts, including, without limitation, statements regarding
our future financial position, business strategy, projected revenues,
earnings, costs, capital expenditures and debt levels, and plans and
objectives of management for future operations, are forward-looking
statements. When used in this news release, words such as we “expect,”
“intend,” “plan,” “estimate,” “anticipate,” “believe” or “should” or the
negative thereof or variations thereon or similar terminology are
generally intended to identify forward-looking statements. Such
forward-looking statements are subject to risks and uncertainties that
could cause actual results to differ materially from those expressed in,
or implied by, such statements.

These risks and uncertainties include, but are not limited to: declines
in oil, NGL or natural gas prices; our level of success in exploration,
development and production activities; adverse weather conditions that
may negatively impact development or production activities; the timing
of our exploration and development expenditures; our ability to obtain
sufficient quantities of CO2 necessary to carry out our
enhanced oil recovery projects; inaccuracies of our reserve estimates or
our assumptions underlying them; revisions to reserve estimates as a
result of changes in commodity prices; risks related to our level of
indebtedness and periodic redeterminations of the borrowing base under
our credit agreement; our ability to generate sufficient cash flows from
operations to meet the internally funded portion of our capital
expenditures budget; our ability to obtain external capital to finance
exploration and development operations and acquisitions; federal and
state initiatives relating to the regulation of hydraulic fracturing;
the potential impact of federal debt reduction initiatives and tax
reform legislation being considered by the U.S. Federal government that
could have a negative effect on the oil and gas industry; impacts of the
global recession and tight credit markets; our ability to identify and
complete acquisitions and to successfully integrate acquired businesses;
unforeseen underperformance of or liabilities associated with acquired
properties; our ability to successfully complete potential asset
dispositions and the risks related thereto; the impacts of hedging on
our results of operations; failure of our properties to yield oil or gas
in commercially viable quantities; uninsured or underinsured losses
resulting from our oil and gas operations; our inability to access oil
and gas markets due to market conditions or operational impediments; the
impact and costs of compliance with laws and regulations governing our
oil and gas operations; our ability to replace our oil and natural gas
reserves; any loss of our senior management or technical personnel;
competition in the oil and gas industry in the regions in which we
operate; risks arising out of our hedging transactions; and other risks
described under the caption “Risk Factors” in our Annual Report on Form
10-K for the period ended December 31, 2012. We assume no obligation,
and disclaim any duty, to update the forward-looking statements in this
news release.

SELECTED FINANCIAL DATA

For further information and discussion on the selected financial data
below, please refer to Whiting Petroleum Corporation's Quarterly Report
on Form 10-Q for the quarter ended March 31, 2013, to be filed with the
Securities and Exchange Commission.

Common stock, $0.001 par value, 300,000,000 shares authorized;
119,389,608 issued and 117,830,572 outstanding as of March
31, 2013, 118,582,477 issued and 117,631,451 outstanding as
of December 31, 2012

Adjusted net income available to common shareholders per share,
diluted

$

0.94

$

1.03

(1)

Adjusted net income available to common shareholders is a non-GAAP
financial measure. Management believes it provides useful
information to investors for analysis of Whiting's fundamental
business on a recurring basis. In addition, management believes that
adjusted net income available to common shareholders is widely used
by professional research analysts and others in valuation,
comparison and investment recommendations of companies in the oil
and gas exploration and production industry, and many investors use
the published research of industry research analysts in making
investment decisions. Adjusted net income available for common
shareholders should not be considered in isolation or as a
substitute for net income, income from operations, net cash provided
by operating activities or other income, cash flow or liquidity
measures under U.S. GAAP and may not be comparable to other
similarly titled measures of other companies.

Discretionary cash flow is computed as net income plus exploration
and impairment costs, depreciation, depletion and amortization,
deferred income taxes, non-cash interest costs, non-cash
compensation plan charges, non-cash losses on mark-to-market
derivatives and other non-current items less the gain on sale of
properties, amortization of deferred gain on sale, non-cash gains on
mark-to-market derivatives, and preferred stock dividends paid. The
non-GAAP measure of discretionary cash flow is presented because
management believes it provides useful information to investors for
analysis of the Company's ability to internally fund acquisitions,
exploration and development. Discretionary cash flow should not be
considered in isolation or as a substitute for net income, income
from operations, net cash provided by operating activities or other
income, cash flow or liquidity measures under U.S. GAAP and may not
be comparable to other similarly titled measures of other companies.

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